Hydrocarbons, such as oil or natural gas, are obtained from hydrocarbon-bearing subterranean geologic formations by drilling wellbores which provide partial flow paths allowing the hydrocarbons to reach the surface. Hydrocarbons migrate via flow paths connecting a reservoir within a formation and a wellbore. However, impeded flow paths can lead to insufficient hydrocarbon production. In such cases, various techniques are used to stimulate the hydrocarbon production. For example, it is common to inject specialized fluids via the wellbore into the formation at sufficient pressures to create fractures in the formation rocks, thereby creating channels through which the hydrocarbons can more readily flow into the wellbore. This technique is referred to as fracturing, or hydraulic fracturing, and the specialized fluids used in the technique are referred to as fracturing fluids.
Ideally, a fracturing fluid imparts a minimal pressure drop in a pipe within the wellbore during placement and has an adequate viscosity to carry proppant material which prevents the fracture from closing. Moreover, the fracturing fluid should have a low leak-off rate, thereby inhibiting fluid migration into the formation rocks and promoting the creation and propagation of the fracture. Further, the fracturing fluid should degrade so as not to leave residual material which might prevent or inhibit hydrocarbon flow into the wellbore.
Early fracturing fluids included viscous or gelled oil, but with the understanding that damage due to water in certain formations may not be as important as originally thought, aqueous fracturing fluids including mainly linear polymeric gels comprising guar or hydroxyethyl cellulose were introduced. Cross-linked polymer gels, such as those based on guar crosslinked with borate or polymers crosslinked with metal ions, were also used to attain a sufficient fluid viscosity and thermal stability in high temperature reservoirs. Thermoviscosifying polymers, containing a hydrosoluble skeleton and side chains having a lower critical solution temperature property, and which have a viscosity which increases or stabilizes with temperature, were disclosed for cementation and fracturing in the oil industry in EP 583,814
However, as it became apparent that polymer residues might deteriorate the permeability of hydrocarbon bearing formations, fluids with lower polymer content were introduced. In addition, additives such as polymer breakers were introduced to improve the clean up of polymer-based fracturing fluids. Nevertheless, minimal formation damages were still attained only with polymer-free fracturing fluids comprising viscoelastic surfactants (VES).
Viscoelastic surfactant molecules, when present at a sufficient concentration, can aggregate into overlapping worm- or rod-like micelles, which confer the necessary viscosity to the fluid to carry the proppant during fracturing. At very high shear rates, e.g., above 170 s−1, the viscosity can decrease, allowing the fluid to be pumped down the wellbore. Also, the surfactant worm- or rod-like micelles tend to disaggregate by contact with hydrocarbons, and without an effective surfactant emulsion, the surfactant molecules are normally carried along the fracture, to the well bore, during the hydrocarbon backflow. The principal advantages of VES fluids are ease of preparation, minimal formation damage and high retained permeability in the proppant pack. Viscoelastic surfactant fluids are disclosed, notably, in the patents published under the numbers U.S. Pat. No. 4,615,825, U.S. Pat. No. 4,725,372, U.S. Pat. No. 4,735,731, CA-1298697, U.S. Pat. No. 5,551,516, U.S. Pat. No. 5,964,295, U.S. Pat. No. 5,979,555 and U.S. Pat. No. 6,232,274. One well-known polymer-free aqueous fracturing fluid comprising a viscoelastic surfactant, which has been commercialized by the company group Schlumberger under the trade designation CLEARFRAC, is a mixture of the quaternary ammonium salt N-erucyl-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride with isopropanol in a brine comprised of, for example, 3 weight percent ammonium chloride and 4 weight percent potassium chloride.
On the other hand, the leak-off rate of VES fracturing fluids is normally high, so they are mainly used with hydrocarbon bearing formations wherein the permeability of the formation rocks is low. In addition, the costs incurred by the use of high-concentration VES systems in aqueous wellbore service fluids, especially fracturing fluids, are elevated.
Polymers and surfactants are often used together in industrial formulations to take advantage of their characteristically different properties. One class of polymers which interact particularly strongly with surfactants is the class of hydrophobically modified water-soluble polymers. See U.S. Pat. No. 4,432,881 to Evani. Since contact between the hydrophobic groups and water is unfavorable, these polymers have a strong tendency to self-associate and/or to associate with surfactants. Progressive addition of surfactants which form spherical micelles typically gives rise to an increase in the viscosity of the solution, followed by a decrease in the viscosity at higher surfactant concentrations. The enhancement in viscosity is typically attributed to the formation of mixed micelles between the polymer alkyl chains and the surfactant molecules, reinforcing polymer intermolecular cross-links. The micelles solubilize alkyl groups belonging to more than one polymer chain, and the system becomes cross-linked.
The use of mixtures of hydrophobically modified polymers and VES for fracturing applications is known, for example, from US 2005/0107503. Those mixed systems present appreciable theological properties, good fluid clean up and sufficient fluid loss control. The hydrophobically-modified polymer, and notably pendant hydrophobic chains of the polymer, interact with the surfactant micelles. As a result, a viscoelastic gel structure can be created at relatively low concentrations of VES and hydrophobically-modified polymer, e.g. the VES below 20 times its overlap concentration and the hydrophobically-modified polymer below its entanglement concentration, thereby limiting cost. The fluid is hydrocarbon-responsive so that the gel structure breaks down on contact or mixing with hydrocarbons. The fluid has a leak-off rate which is below the leak-off rate of pure VES fluids of equivalent rheology. As a result, the fluid can be used to fracture higher permeability formations as compared to the pure VES fluids. The clean-up performance of the fluid is likely to be similar or better than that observed for a low concentration linear polymer fracturing fluid. Moreover, the fluid loss properties of the fluid can be improved by the addition of colloidal particles as reported in U.S. Pat. No. 7,081,439.
Unfortunately, the use of fluids with hydrophobically-modified polymers in the prior art presents a significant practical limitation, particularly for recovery of hydrocarbons. Hydrophobically modified polymers can have a slow hydration rate, making the onsite preparation of fluids containing them difficult and slow to prepare, especially at the injection well bore. The preparation of the treatment fluid at the surface of the well before its injection is important. The hydrophobically modified polymer component of the prior art VES-polymer well treatment fluids must thus be packaged in a liquid form, because if it is in a solid form, it cannot be easily and quickly hydrated.
Accordingly, there is a need for treatment fluids which are readily hydratable, have viscosity properties which enable efficient pumping and proppant transport down a borehole and have good clean up properties, and methods for treating subterranean formations using the fluids.